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The expanding solvent-steam-assisted gravity drainage (ES-SAGD) is a newly proposed thermal recovery technique showing promising efficiency in terms of a smaller steam-to-oil ratio and greater production rate to recover heavy oils and bitumen from oil-bearing formations, where a solvent is coinjected with the steam in the SAGD process. Numerical simulation of the ES-SAGD process requires reliable relative permeability data. The number of reported measurements of relative permeability involving bitumen systems is limited in the literature, mostly because of the experimental difficulties involved in such measurements. The relative permeability data sets for Canadian bitumen, in the presence of solvents, are simply not available in the open literature. The fluid-flow behavior of bitumen/water systems in the presence of solvent is an important matter that must be assessed before the implementation of any ES-SAGD process; therefore, the objective of the current study is to evaluate the impact of a light hydrocarbon solvent (n-hexane) on bitumen/water relative permeability under SAGD conditions. For this purpose, two-phase bitumen/water relative-permeability measurements were conducted in sandpacks over a wide range of temperatures from 70°C to 220°C using Athabasca bitumen, deionized water, and a light hydrocarbon solvent. A well-instrumented experimental setup was developed to perform the relative permeability measurements with the capability of applying confining pressure on the sand and measuring the pore-pressure profile with several intermediate pressure taps. Isothermal oil-displacement tests were carried out with solvent premixed with bitumen. The history-matching approach and Johnson-Bossler-Naumann (JBN) method were used to translate the oil displacement data into the relative-permeability curves. The results obtained with a solvent from this study and without any solvent reported in our previous study are compared to assess the solvent’s impact on relative permeability. In addition, the steady-state relative permeability was measured to assess the reliability of unsteady-state relative permeability. The interfacial tension (IFT) and contact-angle measurements using the same fluids were carried out to determine the fluid/fluid interaction and wettability state of the system under high-pressure/high-temperature (HP/HT) conditions.
The results of the present study confirmed that the two-phase diluted bitumen/water relative permeability is sensitive to temperature, especially in terms of the endpoint relative permeability to bitumen and water. Furthermore, adding normal hexane (below the asphaltene precipitation threshold) not only improves the displacement efficiency of water flooding because of the significant decrease in oil viscosity but also modifies the wettability and IFT of this system. At the same temperature, the two-phase oil/water relative permeability for bitumen/water systems is significantly different when the oil is diluted with the solvent. Also, the impact of solvent is more pronounced at lower temperatures. Furthermore, the consistency between the steady-state and unsteady-state relative permeability data proved that the effect of viscous fingering was small enough.
Invasion of mud filtrate while drilling is considered one of the most common sources of formation damage. Minimizing formation damage, using appropriate drilling-fluid additives that can generate good-quality filter cake, provides one of the key elements for the success of the drilling operation. This study focuses on assessing the effect of using different types of nanoparticles (NPs) with calcium- (Ca-) bentonite on the formation-damage and filter-cake properties under downhole conditions.
Four types of oxide NPs were added to a suspension of 7-wt% Ca-bentonite with deionized water: ferric oxide (Fe2O3), magnetic iron oxide (Fe3O4), zinc oxide (ZnO), and silica (SiO2) NPs. The NPs/Ca-bentonite suspensions were then used to conduct the filtration process at a differential pressure of 300 psi and a temperature of 250°F using a high-pressure/high-temperature (HP/HT) American Petroleum Institute (API) filter press. Indiana limestone disks of 1-in. thickness were examined as the filter medium to simulate the formation in the filtration experiments. A computed tomography (CT) scan technique was used to characterize the deposited filter cake and evaluate the formation damage that was caused by using different fluid samples.
The results of this study showed that the filtrate invasion is affected by the type of NPs, which is also affecting the disk porosity. Using 0.5-wt% Fe2O3 NPs with the 7-wt% Ca-bentonite fluid showed a greater potential to minimize the amount of damage. The average porosity of the disk was decreased by 1.0%. However, adding 0.5-wt% Fe3O4, SiO2, and ZnO NPs yielded a disk-porosity decrease of 4.7, 13.7, and 30%, respectively. The decrease in the disk porosity after filtration is directly proportional to the volume of the invaded filtrate. Compared with that of the base fluid, the best decrease in the filtrate invasion was achieved when adding 0.5 wt% Fe2O3 and Fe3O4 NPs by 42.5 and 23%, respectively. The results revealed that Fe2O3 and Fe3O4 NPs can build a better Ca-bentonite platelet structure and thus a good-quality filter cake. This is because of their positive surface charge and stability in suspensions, as demonstrated by zeta-potential measurements, which can minimize formation damage. Increasing the concentration of Fe3O4 NPs from 0.5% to 1.5 wt% showed an insignificant variation in the filtrate invasion, spurt loss, and filter cake permeability; however, an increase in the filter-cake thickness and amount of damage created was observed. The 1.5-wt% ZnO NPs showed better performance compared with the case having 0.5-wt% ZnO NPs, but in the meanwhile, it showed the lowest efficiency compared with the other types of NPs. This could be because of their surface charge and suspension instability.
Results of this work are useful in evaluating the drilling applications using Ca-bentonite-based fluids modified with NPs as an alternative to the commonly used Na-bentonite. In addition, it might help in understanding the NPs/Ca-bentonite interaction for providing more efficient drilling operations and less formation damage.
The rotating disk apparatus (RDA) is used to study reaction kinetics. However, the current equations used to interpret the results from the RDA make oversimplifying assumptions. Some of these assumptions are not met in practice, yet no work has been done to study their impact on the mass transfer of the proton (H+) to the disk. The objectives of the current work are threefold: study flow regimes under the rotating disk in the RDA for Newtonian and non-Newtonian fluids, investigate the impact of the reactor boundaries on the mass transfer of H+ to the disk in Newtonian fluids, and identify the dimensions of the reactor that minimize this impact.
The mass transfer of the H+ was compared between different dimension reactors. Contrary to information reported in the literature, both the diameter of the reactor and the axial distance between the base of the disk and the bottom of the reactor have an impact on the rate of mass transfer of H+ to the disk. Moreover, the velocity profiles in the reactor showed three flow regimes: fully axisymmetric, fully asymmetric flow, and intermediate flow. These different regimes varied depending on the axial distance between the base of the disk and the bottom of the reactor, the diameter of the reactor, the rotational speed of the disk, and the kinematic viscosity of the reacting fluid.
Hydrocarbon (re-)development projects need to be evaluated under uncertainty. Forecasting oil and gas production needs to capture the ranges of the multitude of uncertain parameters and their impact on the forecast to maximize the value of the project for the company. Several authors showed, however, that the oil and gas industry has challenges in adequately assessing the distributions of hydrocarbon production forecasts.
The methods for forecasting hydrocarbon production developed with digitalization from using analytical solutions to numerical models with an increasing number of gridblocks (“digital twins”) toward ensembles of models covering the uncertainty of the various parameters. Analytical solutions and single numerical models allow calculation of incremental production for a single case. However, neither the uncertainty of the forecasts nor the question in which the distribution of various outcomes the single model is located can be determined. Ensemble-based forecasts are able to address these questions, but they need to be able to cover a large number of uncertain parameters and the amount of data that is generated accordingly.
Theory-guided data science (TGDS) approaches have recently been used to overcome these challenges. Such approaches make use of the scientific knowledge captured in numerical models to generate a sufficiently large data set to apply data science approaches. These approaches can be combined with economics to determine the desirability of a project for a company (expected utility). Quantitative decision analysis, including a value of information (VoI) calculation, can be done addressing the uncertainty range but also the risk hurdles as required by the decision-maker (DM). The next step is the development of learning agent systems (agent: autonomous, goal-directed entity that observes and acts upon an environment) that are able to cope with the large amount of data generated by sensors and to use them for conditioning models to data and use the data in decision analysis.
Companies need to address the challenges of data democratization to integrate and use the available data, organizational agility, and the development of data science skills but making sure that the technical skills, which are required for the TGDS approach, are kept.
This paper presents a case history of scale treatments performed in a well producing in the North Sea. Kvitebjørn is a gas and condensate producer with high reservoir pressure (480bar) and high temperature (152°C). Well A-7 T2 started production in January 2014 and has a history of a carbonate scale precipitation.A few months after start-up, formation water breakthrough was observed in addition to a reduction in Production Index.
Due to challenges with removing scale by wireline, interventions using scale dissolver were performed in late 2017 and early 2018. The second dissolver treatment was followed by a scale squeeze to protect the well from further scaling. The chemicals used were qualified according to the Operator’s technical specifications. Due to high reservoir temperature, thermal stability was vital in the qualification process. The formation permeability was moderate, which was important to consider when evaluating the risk of formation damage.
The environmental category for the chemicals versus their performance was an important factor in the qualification process. Modelling programs were used to assess placement distribution under various bullhead pumping conditions. For the scale squeeze, a modelling program was used to simulate treatment lifetime using isotherms derived from laboratory core flood testing.
Water samples were taken from the well and analysed onshore in the supplier’s laboratory. Following the scale squeeze, water samples were taken from the well during the entire treatment lifetime. Ion concentrations and residual inhibitor concentrations were monitored together with production parameters to assess the scale situation in the well.
Following the treatments, the well showed an increased gas production. The well produced 1.2MSm3 at 40% choke before the treatments and 1.2MSm3 at 6-7% choke after. Laboratory work combined with field experience from this first well that was treated, forms the basis for possible future treatments. Being able to treat wells through pro-active and efficient scale inhibitor squeeze treatments will allow for continued production of wells exposed to scale risk, avoiding the cost and risks associated with mechanical scale removal and avoiding production deferral associated with potential dissolver jobs.
Scale control and inhibition is very important for maintaining flow assurance of oil production. Several specialty chemicals are used to delay, reduce or prevent scale deposition and, in particular, polymers and phosphonate-based chemicals have been used extensively. The accurate and precise topside measurement of scale inhibitors plays an important role in assessing the efficiency of scale squeeze and continuous-chemical injection treatments. At present, numerous techniques exist for scale inhibitor (SI) analysis but each method has its own limitation and often these methods give results of either total chemical content or elemental analysis without details of chemical speciation. Furthermore, most techniques often lack the ability for on-site analysis on fresh produced water samples, which yields the potential for quick and more accurate and precise information due to minimal sample degradation.Nanotechnology-based Surface Enhanced Raman Spectroscopy (SERS) developed as the next-generation method to fill the gap in speciation of phosphonates and to determine low concentrations of different scale inhibitor chemicals in produced brines in a timely and cost-effective manner.Particular focus is placed upon the individual and mixed analysis of a novel phosphonate and Deta Phosphonate (DETPMP) respectively. Development of this method with handheld instrumentation provides better detection and quantification of scale inhibitors in the field and reduces time and cost compared to sending samples to off-site laboratories for data collection.
The control of inorganic scale deposition within production wells by deployment of scale squeeze treatments is a well-established method for both onshore and offshore production wells. Factors that have influenced the change from 12 to 24 months squeeze treatments include changing MIC values, rising operation expenditure related to subsea vs platform deployment costs and in all cases assessing total operational cost vs simply chemical costs alone. The implication of deferred oil associated with delayed production during pumping and post squeeze well cleanup was also considered in the design process for these wells. The paper outlines the elements of the process that should be considered/reviewed when making the decision to change from the conventional 12 months to 24 months squeeze treatment. Designs and field results from three oil producing basins, each with different cost drivers, have been used to illustrate how it is possible to maintain effective scale management through the life cycle of these production wells. 2 SPE-200701-MS
Paudyal, Samridhdi (Brine Chemistry Consortium, Rice University) | Mateen, Sana (Brine Chemistry Consortium, Rice University) | Dai, Chong (Brine Chemistry Consortium, Rice University) | Ko, Saebom (Brine Chemistry Consortium, Rice University) | Wang, Xin (Brine Chemistry Consortium, Rice University) | Deng, Guannan (Brine Chemistry Consortium, Rice University) | Lu, Alex (Brine Chemistry Consortium, Rice University) | Zhao, Yue (Brine Chemistry Consortium, Rice University) | Bingjie, Ouyang (Brine Chemistry Consortium, Rice University) | Kan, Amy T. (Brine Chemistry Consortium, Rice University) | Tomson, Mason B. (Brine Chemistry Consortium, Rice University)
Calcium Sulfate (CaSO4) is precipitated due to super saturation of Ca2+ and SO42-ions that can be created due to change pH, pressure, temperature or due to mixing of the brines. Among the CaSO4 species, CaSO4.2H2O or gypsum is stable in solid phase at lower temperature below 50 °C which has been observed frequently in wells treated with CO2 flooded-EOR technique. As a result, mineral scaling, especially calcium sulfate (gypsum) deposition has been a serious flow assurance problem in oil and gas production leading to production shut down because of formation damage or equipment failure. Use of scale inhibitors may be the efficient method to prevent the scale formation. However, there is a knowledge gap on types of scale inhibitor that might be efficient in controlling the calcium sulfate scaling under varied field conditions. Additionally, there is a need of an efficient method to evaluate the performance of scale inhibitor and simulate the dynamic field condition.
This study provides information on several options of inhibitors to control CaSO4 at various conditions as established with modified laser-light based Kinetic Turbidity Test (mKTT) method that can assess several samples over a range of concentrations simultaneously. Other newly developed modified Continuous Stirred Tank Reactor (mCSTR) method showed to be an efficient tool to understand scale inhibitor performances, as it can overcome limitations of dynamic scale loop (DSL) with low residence time and low volume capacity of capillary tubing. Similarly, as minimum effective dosage (MED) needed can be easily established in one setting with mCSTR method. It showed much better efficiency compared to that of standard bottle test, which suffers lack of dynamics and multiple bottle tests needed to establish MED. This study provides more effective test methodologies for scale inhibitors performance testing. The mCSTR apparatus can be used for various mineral scales such as barium sulfate, halite, calcite, etc. Additionally, this study will provide a mathematical model (scaling risk-inhibitor dosage recommendation) via mCSTR method which can be used to predict scaling tendency and inhibitor need under desired conditions.
Ko, Saebom (Rice University) | Wang, Xin (Rice University) | Zhao, Yue (Rice University) | Dai, Chong (Rice University) | Lu, Yi-Tsung (Rice University) | Deng, Guannan (Rice University) | Paudyal, Samridhdi (Rice University) | Mateen, Sana (Rice University) | Kan, Amy T. (Rice University) | Tomson, Mason B. (Rice University)
Scale formation in oil and gas wells commonly occurs, causing not only pipeline blockage, equipment failure, or formation damage during production, trasnsportation, and treatment, but also premature abandonment of wells in serious cases. Although types of mineral scale occurrence depend on the types of ions in water, sulfate and carbonate scales are the most commonly found scales in oil and gas fields. In this study, we investigated a single approach to prevent complex mineral scales from deposition using water-soluble polymer dispersant or the combination of water-soluble polymer dispersant of carboxymethyl cellulose (CMC) and phosphonate inhibitors of diethylene triamine penta(methylene phosphonic) acid (DTPMP) or hexamethylene diaminetetra (methylene phosphonic) acid (HDTMP) in highly saturated solution or high ionic strength (IS) brines. This study shows that CMC effectively prevents sulfate (barite and gypsum) and carbonate (calcite nd iron carbonate) scales from deposition. The particle size dispersed in the presence of CMC remains in nanosize ranges. When CMC was combined with phosphonate inhibitors of DTPMP or HDTMP, sulfate scales were even more effectively controlled, compare to CMC or phosphonate inhibitors by themselves. In the combination of CMC and DTPMP, the majority of barite (> 90%) remained in a size of smaller than 200 nm and the total mass of barite deposition on 316 stainless steel coupon was negligible, as low as 0.079% of total input mass. Gypsum formation was inhibited for at least 6 hours and gypsum particles remained in a size of smaller than 200 nm for 12 hours in the combination of CMC and HDTPM. For calcite, measured induction time was 134 minutes and calcite particles were dispersed for at least 15 hours with its average particle size of 396 nm in the presence of CMC. Iron carbonate particles were well dispersed for 2 hours in the presence of CMC.
Yue, Zhiwei David (Halliburton) | Chen, Ping (Halliburton) | Draghici, Vlad (Halliburton) | Westerman, Megan (Halliburton) | Huijgen, Martijn (Halliburton) | Privitera, Angelo (Halliburton) | Hazlewood, John (Halliburton) | Hagen, Thomas (Halliburton)
An oilfield operator relies extensively on heat exchangers (Hexs) to break heavy oil emulsions. A workhorse inhibitor worked reliably to control thermally induced scale precipitation caused by local hard waters. However, an upsurge of scale-related Hexs tubing blockage occurred during a harsh winter that coincided with a breakthrough of enhanced oil recovery (EOR) polymer into some water sources. Through comprehensive lab testing, root causes of the failure were identified. A new product was developed featuring superior tolerance to variable production parameters, especially Hexs temperatures.
Scale inhibitor efficacy is strongly influenced by overall scaling conditions including water chemistry, temperature, pressure, and presence of incompatible chemicals. In this study, scale precipitates collected from Hexs were characterized using environmental scanning electron microscopy techniques. New inhibitor chemistries were screened through thermal aging; then evaluated for inhibition performance by dynamic tube blocking methods at temperatures ranging from 42°C to 171°C. An additional performance test was designed for the final candidate to further investigate adverse impacts from the EOR polymer and incumbent scale product if a dual-product treatment is required throughout the field fluid system.
The incumbent effectively inhibited scale formation at ≤120°C but showed reduced performance at 160°C. This result is consistent with field records indicating most tubing blockages occurred during the coldest days when Hexs temperature was raised to 160°C to increase heat to treat fluids. Meanwhile, it also suffered antagonistic effects from the EOR polymer. A dozen new inhibitor chemistries were studied including polymers and phosphonates. Polymeric inhibitors had higher thermal aging ratings but were less compatible with the waters involved. Ideal candidates must have thermal stability, high-temperature inhibition performance, and applicability to wide ranges of operational conditions, including Hexs temperature, water hardness, bicarbonate, and foreign substances. Thus, a single product can be applied to the entire field and simple dosage adjustments can readily handle most expected scaling risks. The new product passed all the criteria and significantly reduced operating and equipment replacement cost since deployment.
This paper provides a unique scaling challenge that combined ultra-high temperature and EOR polymer influence, and a systematic approach to understanding and resolving the issue.